1. Field of the Invention
The present invention relates generally to subterranean formation evaluation, and more specifically to a one trip subterranean well test assembly.
2. Description of the Related Art
Many new subterranean wells are drilled both onshore and offshore for exploration or appraisal of potential reservoirs for the purpose of continuously expanding hydrocarbon reserves. Recently more effort has been made towards exploring tight and unconventional resources. Because well testing conventionally requires a long rig static time and associated significant costs, recent practice has evolved towards rig-less well testing. In many cases, such practice requires each exploration or appraisal well to be completed with 4½″ monobore tie-back before the rig is released. Later the well is tested by appropriate downhole test tools that are conveyed by a combination of coiled tubing and wireline or slickline.
Current well test practice often creates a large wellbore storage factor of up to a few thousand feet below the zonal isolation device or test packer, particularly during testing a deep target zone across a long 4½″ cemented liner, because a shut-in tool is required to be run separately and generally hanged and sealed across a profile-nipple that is located either just below or above a packer, which is a fixed location once well is completed.
Traditionally well tests have been conducted inside a 7″ liner for a cased hole test or inside a 8⅜″ hole for a barefoot test. However to assure drilling 8⅜″ hole in a deep exploration primary target zone and run and cement 7″ liner requires considerably more rig time due to a bigger well casing design required from the surface and the associated extra well cost. As a result, 5⅞″ open hole installed with 4½″ liner has been accepted as an economical and achievable alternative for the purpose for testing multiple zones of interests. For exploration wells, running and cementing 4½″ liner inside a 5⅞″ hole across targeted formations is sometimes unavoidable due to the unforeseen nature of drilling exploration wells that may force down the final casing size for the primary target zone because of up-hole drilling troubles requiring a casing or liner to actually and effectively resolve the problems, even if the well has a bigger casing design from surface.
This situation becomes nevertheless more challenging when testing tight or unconventional reservoir type formations, where movable hydrocarbon, if it exists, is only able to flow into the wellbore in a very limited volume because of poor permeability in the surrounding area of the wellbore and the allowed practical test time. This could result in the inability to flow well fluids to surface, and therefore there will be no wellhead pressure during flow test. For a wellbore with large storage space, such as when dealing with compressible gases in the wellbore, the recorded downhole data during pressure build-up test in such case could be less clear or even non-conclusive. As a result, an exploration well may simply declared as a ‘dry’ hole or uneconomical, even though there may be a limited flow of mobile hydrocarbon that are difficult to detect and properly evaluate with current technology in use.
In some current practice of rig-less well test for exploration and appraisal effort, a well is completed with slim-hole, such as 4½″ monobore tubing tie-back with cemented 4½″ liner across the targeted test zones. The operator can run in the hole with a wireline perforation gun, perforate as per plan, and then pull out of the hole with the fired gun. If required, coiled tubing is rigged and run into the slim-hole of the well to perform acid stimulation, and then the coiled tubing is pulled out of the well. The well is opened for flow on a pre-set choke to pressurize a gauge tank and record return data every minute. If the well has no flow or the wellhead pressure drops to zero, coiled tubing is rigged up and run into the hole to pump nitrogen gas lift, while diverting the return fluids to the flare pit. The well is then flowed until stabilization is achieved, and then the choke size is increased. While flowing the well through a test separator, the recorded flowing parameters are recorded, such as: flowing wellhead pressure, flowing wellhead temperature, choke size, tubing casing annulus pressure, background solids and water percentages, H2S, CO2, pH, oil rate, water rate, gas rate, total gas to oil ratio, chloride content, oil gravity and gas gravity. Samples of produced gas and liquid can be collected for later analyses.
A downhole shut-in tool and gauges can be run on wireline or slickline and hung across the R profile nipple either below or above the production packer. The well can continue to flow for a while, and then be shut in electronically by the downhole shut-in tool. The final pressure build-up can be recorded by memory gauges. The downhole shut-in tool and gauges can be pulled out of the hole. Coiled tubing can be run into the well and the well can be killed with weighted fluid. A bridge plug can be lowered into the well on a wireline and set, and then pressure tested from above. These steps may be repeated for another test zone in an upper interval.